This invention relates to processing gas streams comprising methane and other hydrocarbons in order to remove the other hydrocarbons.
Natural gas often contains high concentrations of natural gas liquids (NGL) including ethane, propane, butane, and higher hydrocarbons, among other compounds. The NGL are often removed in a gas processing plant prior to supplying methane to a pipeline (e.g., in order to meet specifications defining the composition of material supplied to the pipeline). The heavy hydrocarbons are typically removed as a mixed liquid product that can be fractionated into valuable purity products, such as ethane which is a chemical feedstock. Any propane and butane present in the NGL can be blended to form liquefied petroleum gas (LPG), a valuable residential fuel. NGL prices tend to be linked to the price of petroleum, thereby increasing the value of the removable NGL when natural gas prices are low but petroleum prices are high.
Conventional options for the removal of NGL include refrigeration, wherein the natural gas is chilled until heavy compounds such as hexanes and heavier (C6+ hydrocarbons) condense out of a feed stream. Another conventional option is absorption, wherein NGL are removed by being contacted with a light oil (e.g. kerosene range), that has high recovery of butanes and heavier (C4+) and moderate recovery of propane. Refrigerating the lean oil to −30 to −40° F. improves propane recovery and can achieve as high as 50% ethane recovery.
In order to achieve 90+% recovery of ethane and 98+% recovery of C3+, cryogenic or turboexpander plants are typically used. These plants use the expansion of the natural gas stream to reduce the temperature to −100 to −150° F. wherein the natural gas is mostly liquid and can be separated using a distillation column. These columns are referred to as demethanizers when the bottoms are C2+ and deethanizers when the bottoms are C3+. Turboexpanders can be used to generate a portion of the compression power for returning the sales gas stream to pipeline pressure. This increases the overall efficiency of the process.
In the late-1970s the Ortloff Corporation developed the gas-subcooled process (GSP) that improved NGL recovery by adding a subcooled reflux stream to the top of the demethanizer. GSP and related processes are the dominant technology used to recover NGL because they are the most cost effective way to achieve high C2 recoveries and maximize the economic output of a natural gas well.
Two key disadvantages of GSP are the compression costs to bring the recovered gas back to pipeline pressure and the lack of flexibility in capacity. GSP plants add capacity via large trains and are less tolerant of turndown than adsorption processes because either the turboexpander will not be able to achieve the low temperatures needed to operate the demethanizer, or the flow rates in the demethanizer will be insufficient to maintain the proper flow patterns.
The optimal efficiency of turboexpander plants comes at an operating point close to full design capacity. As feed rate rises, there can be multiple equipment-related bottlenecks that prevent further plant loading. These include limitations associated with excessive vapor flow rate in the demethanizer causing entrainment or flooding, lack of refrigeration, inability to compress the residue gas to pipeline pressure, or lower NGL recovery leading to a residue gas with a heating value that exceeds pipeline specifications.
Certain conventional adsorption processes are well known for removing NGL from natural gas streams and have the advantage of maintaining the sales gas at an elevated pressure. However, these processes suffer from lower methane recovery rates than any other technology described above. Whereas GSP recovers well over 99% of the methane, even the best adsorption process will have recoveries in the 75-85% range because some of the natural gas feed will be used to regenerate the bed.
Conventional NGL processing systems are disclosed by M. Mitariten (U.S. Pat. No. 7,396,388 and U.S. Pat. No. 7,442,233) which provides an integrated system of Pressure Swing Adsorption (PSA), amine scrubbing, and adsorptive water adsorption that removes acid gases, water, and heavy hydrocarbons (C4+) from a natural gas stream.
Dolan and Butwell (U.S. Pat. No. 6,444,012) teach the use of a PSA to reject C3+ components from a raw natural gas feed combined with a second N2-rejection PSA to produce an enriched CH4 stream. The product stream from the second PSA is used to regenerate the first PSA and recover the heating value of the higher alkanes in the methane product.
Butwell et al. (U.S. Pat. No. 6,497,750) also teach two PSAs in series for N2 rejection from methane. The first PSA removes N2 from raw natural gas. The waste stream from this PSA contains N2, CH4, and heavies, and is compressed and passed to the second PSA containing a CH4-selective adsorbent to produce an N2 product. The waste stream from this second PSA is CH4-rich and is recycled to the first PSA after removal of heavies by refrigeration.
B. T. Kelley et al. (US 2008/0282884) describe a monolith adsorbent in a PSA system that discloses C1/CO2 and C1/N2 separation.
Avila et al. (“Extraction of ethane from natural gas at high pressure by adsorption on Na-ETS-10,” Chem. Eng. Sci. 66:2991-2996, 2011) describes a very high selectivity of ethane over methane in a modified zeolite.
Maurer (U.S. Pat. No. 5,171,333) teaches methane purification by PSA using ZnX and CaY zeolite adsorbent.
W. C. Kratz et al. (U.S. Pat. No. 5,840,099) describes a combined pressure swing/vacuum swing adsorption unit to remove water, CO2, C3+, and some ethane from a natural gas stream so that the methane-rich stream could be used as a transportation fuel.
The disclosure of the previously identified patents, patent applications and publications are hereby incorporated by reference.
There is a need in this art for an improved system and method for removing NGL from natural gas. More specifically, there is a need for a mobile separation system that can be used to effectively debottleneck an existing gas plant.